In numerous industrial environments, a hydrocarbon fuel is burned in stationary combustors (e.g., boilers or furnaces) to produce heat to raise the temperature of a fluid, such as water. For example, water is heated to generate steam, which is then used to drive turbine generators that output electrical power. Such industrial combustors typically employ an array of many individual burner elements to combust the fuel. In addition, various combustion control techniques, such as overfire air, staging air, reburning systems, and selective non-catalytic reduction systems, can be employed to enhance combustion conditions and reduce oxides of nitrogen (“NOx”) emission.
For a combustor to operate efficiently and to produce an acceptably complete combustion that generates by-products falling within the limits imposed by environmental regulations and design constraints, all individual burners in the combustor should operate cleanly and efficiently, and all combustion modification systems should be properly balanced and adjusted. Emissions of NOx, carbon monoxide (“CO”), mercury (“Hg”), and/or other by-products (e.g., unburned carbon or loss-on-ignition (“LOI”) data) generally are monitored to provide compliance with environmental regulations and acceptable system operation. The monitoring heretofore has been done, by necessity, on the aggregate emissions from the combustor, such as on the entire burner array, taken as a whole, without providing an analysis on each individual burner and/or varied conditions within the burner.
Some emissions, such as the concentration of unburned carbon in fly ash and Hg can be difficult to monitor online and continuously. In many cases, these emissions are conventionally measured on a periodic or occasional basis by extracting a sample of ash and sending the sample to a laboratory for analysis. When a particular combustion by-product is found to be produced at unacceptably high concentrations, the combustor is adjusted to restore desired operating conditions. Measurement of the aggregate emissions, or measurement of emissions on a periodic or occasional basis, however, does not provide an indication of what combustor parameters should be changed and/or which combustor zone should be adjusted.
The air-to-fuel ratios between each burner in a combustor of a boiler can vary considerably because the burner air and pulverized coal distributions can vary significantly from burner to burner. The absence of effective methods to adequately monitor and control the coal and air flows can contribute to a boiler not operating under its optimal combustion conditions. The variance in burner coal and air flow rates can lead to a wide variance in individual burner operating conditions, some operating on the fuel-rich side and some on the fuel-lean side of the average boiler air-to-fuel ratio. The burners operating on the fuel-rich side produce significant unburned combustion by-products (e.g., CO and LOI) that may not be completely oxidized downstream by mixing with excess air from fuel-lean burners. The degree to which a fuel-rich burner's unburned by-products are oxidized depends on the proximity of the fuel-lean burners, the degree of mixing, and the mixed burner stream temperature. The final unburned by-product levels restrict the boiler from operating at lower excess air levels, which has the effect of driving fuel-rich burners richer and producing more unburned by-products, as well as reducing the availability of excess air from fuel-lean burners to burn-out by-products of the fuel-rich burners. One result of these out of balance burner conditions is that boilers may be operated at higher excess air levels. The levels of excess air are dictated by the amount of imbalance in the burner's air-to-fuel ratios. As a result of the operation under high excess air, there can be an increase in NOx emissions and a reduction in the boiler's efficiency, which increases operational costs for fuel and NOx credits and also reduces output due to emissions caps.
In some plants, boilers are operated with high excess air in order to increase combustion gas mass flow and subsequent heat transfer in the convective pass to achieve desired steam temperatures. In these applications, burner imbalance can have an impact on gas temperature uniformity. For fossil fuel fired boilers, peak combustion temperatures are reached at slightly fuel-rich operation. These peak temperatures caused by fuel-rich burners can lead to increased metal fatigue, slagging (melted ash) deposits on convective passes, corrosive gases, and high ash loadings in local convective pass regions. To remove ash and slagging, additional sootblowing is required. Sootblowing, high temperature gases, and corrosive gases can lead to the deterioration of watertube and waterwall metals, which can result in frequent forced outages due to tube or other component failures and, thus, lost power generation capability. Currently, to avoid potentially catastrophic failure due to high temperature metal fatigue in convective passes, the boiler may be “derated.” This means the boiler is operated below the rated capacity, which reduces the total heat input and reduces the gas temperature exiting the furnace prior to the convective passes.
Thus, there exists a need for improved methods and systems for analyzing boiler operation.